Wellsite sensor assembly and method of using same

ABSTRACT

Some embodiments include a sensor assembly comprising a sensor to be carried by a movable component movably positionable about a tool body of a downhole tool. The sensor is to take wellsite measurements and the downhole tool is positionable in a wellbore. The sensor assembly further includes electronics positionable in the movable component. The electronics are to electrically connect to the sensor to receive the wellsite measurements from the sensor, and the wellsite measurements are usable to determine wellsite parameters.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a 35 U.S.C. § 371 national stage entry ofPCT/US2016/028525, filed Apr. 20, 2016, which claims the benefit of USProvisional Application No. 62/150,217, filed Apr. 20, 2015, the entirecontents of each being hereby incorporated by reference herein for allpurposes.

BACKGROUND

This present disclosure relates generally to techniques for performingwellsite operations. More specifically, the present disclosure relatesto well site equipment, such as drilling and/or sensing devices.

Oilfield operations may be performed to locate and gather valuablesubsurface fluids. Oil rigs are positioned at wellsites, and subsurfaceequipment, such as a drilling tool, is deployed into the ground by adrill string to reach subsurface reservoirs. At the surface, an oil rigis provided to deploy stands of pipe into the wellbore to form the drillstring. Various surface equipment, such as a top drive, a Kelly, and arotating table, may be used to apply torque to the stands of pipe andthreadedly connect the stands of pipe together. A drill bit is mountedon the subsurface end of the drill string, and advanced into the earthfrom the surface to form a wellbore.

The drill string maybe provided with various subsurface components, suchas a bottom hole assembly (BHA), measurement while drilling (MWD),logging while drilling (LWD), telemetry and other drilling tools, toperform various subsurface operations, such as providing power to thedrill bit to drill the wellbore and performing subsurface measurements.

The bit may be advanced into the earth to form the well bore. Thedrilling tool may also be provided with a reamer to assist in enlargingthe wellbore during drilling. Examples of reamers are provided in USPatent/Application Nos. 2010/0181115, 2012/0055714, U.S. Pat. Nos.8,307,921, 7,823,663, 7,703,553, 7,958,953, 6,279,670, and 6,615,933,the entire contents of which are hereby incorporate by reference herein.

SUMMARY

In at least one aspect, the disclosure relates to a wear sensorcomprising a base positionable about a surface, a plurality ofconductive layers stacked on the base, and a plurality of vias extendingthrough the plurality of conductive layers and to the base. Theconductive layers define a wear surface. Each of the conductive layersis electrically connected to at least two of the vias. The two vias areconnected electrically in parallel to one another. The vias areelectrically connected to electronics to generate a signal through theplurality of vias whereby, upon wear of each of the plurality ofconductive layers, a change in the signal of a corresponding of the atleast two of the plurality of vias at a depth of the wear is detectable.

The vias may comprise base vias and/or conductor vias. The base vias maybe in electrical communication with the base, and may comprise aconductor extending therethrough. The conductor may be electricallycoupled to a corresponding one of the plurality of conductive layers andto the base. The conductor vias may be distributed about each of theconductive layers. The conductor vias may comprise ten conductor viasextending along a length of the plurality of conductive layers.

Each of the conductor vias may comprise a conductor portion electricallycoupled to a corresponding one of the plurality of conductive layers andan insulated portion electrically insulated from a remaining portion ofthe plurality of conductive layers. The vias may comprise base vias andconductor vias. Each of the base vias and each of the conductor vias maybe in electrical communication with a corresponding one of the pluralityof conductive layers. The conductor vias may be in electricalcommunication with the base vias through the corresponding one of theconductive layers. The base vias may be electrically connected to theelectronics to generate a signal through the vias. The vias may betubular members extending vertically through the conductive layers fromthe wear surface to the base. The vias may be positioned parallel toeach other. The conductive layers may comprise copper.

In another aspect, the disclosure relates to a method of sensing wear.The method involves providing a wear sensor comprising a basepositionable about a surface, a plurality of conductive layers stackedon the base; and a plurality of vias extending through the plurality ofconductive layers and to the base. The conductive layers define a wearsurface. The method also involves electrically connecting each of theplurality of conductive layers to at least two of the plurality of vias,electrically connecting in parallel the at least two of the plurality ofvias, generating a signal through the plurality of vias by electricallyconnecting the plurality of vias to electronics, and detecting a depthof wear by detecting a change in the signal of the at least two of theplurality of vias at the depth of wear.

The detecting may involve measuring the signal across more than one ofthe plurality of vias distributed about the plurality of conductivelayers and wherein the detecting comprises detecting the change in thesignal from the more than one of the plurality of vias, and/or passingthe signal from each of the plurality of conductive layers via aplurality of signal lines to the electronics for the detecting. Thegenerating may involve passing the signal from each of the plurality ofconductive layers via a plurality of signal lines, applying a resistanceto each of the plurality of signal lines, and passing the signals to theelectronics through a combined signal line for the detecting. Thegenerating may involve passing the signals from each of the plurality ofconductive layers through an analog to digital converter and to theelectronics through at least one signal line for the detecting, and/orpassing the signals from each of the plurality of conductive layersthrough a multiplexer and to the electronics through at least one signalline for the detecting.

In yet another aspect, the disclosure relates to a sensor assembly for adownhole tool positionable in a wellbore, the downhole tool comprising atool body and a movable component movably positionable about the toolbody. The sensor assembly comprises a sensor carried by the movablecomponent to take well site measurements, and electronics positioned inthe movable component. The electronics are electrically connected to thesensor to receive the well site measurements therefrom whereby well siteparameters are determinable.

The sensor may comprise a position sensor in communication with areference positioned in the tool body of the downhole tool, and/or awear sensor positioned about a surface of the movable component. Thesensor assembly may also include seals positioned about the sensor, achassis carried by the movable component, the chassis comprising asidewall with an electronics chamber to receive the electronics therein,a plug positionable about an opening of the chassis, a bracket to securethe chassis to the movable component, and/or a disc coupled to thechassis, the sensor comprising a position sensor carried by the disc.The electronics may be positioned on an electronics board, may comprisebatteries, and/or may comprise a signal converter, an analog to digitalconverter, a multiplexer, pull-up resistors, line resistors, a memory, acommunicator, sensors, a microcontroller, a field programmable gatearray, a receiver, a transmitter, and combinations thereof.

Finally, in another aspect the disclosure relates to a sensor assemblyfor a downhole tool positionable in a well bore penetrating asubterranean formation. The downhole tool comprises a tool body and amovable component movably positionable about the tool body. The sensorassembly comprises references carried by the tool body, a positionsensor carried by the movable component to detect the proximity of theposition sensor to the references, a wear sensor positioned about asurface of the movable component to detect wear, and electronics carriedby the movable component and electrically connected to the positionsensor and the wear sensor to receive signals therefrom whereby positionand wear of the movable component are determined.

The position sensor and the references may comprise magnets. Theposition sensor may comprise north magnetic sensors, south magneticsensors, and/or bi-polar sensors. The sensor assembly further comprisesa chassis carried by the movable component. The electronics arepositioned in the chassis. The position sensor may comprise a disc withthe position sensors on upper and lower surfaces thereof. The disc isconnected to the chassis by a stem with a wired connection therethrough.The wired connection may electrically connect the position sensors tothe electronics. The wear sensor may comprise a core having a wearsurface and conductors positioned at depths about the core, theconductors electrically connected to the electronics. The chassis maycomprise a sidewall with an opening and a plug positioned about theopening.

In yet another aspect, the disclosure relates to a downhole toolpositionable in a wellbore penetrating a subterranean formation. Thedownhole tool comprises a tool body, a movable component movablypositionable about the tool body, and a sensor assembly. The sensorassembly comprises references carried by the tool body, a positionsensor carried by the movable component to detect the proximity of theposition sensor to the references, a wear sensor positioned about asurface of the movable component to detect wear, and electronics carriedby the movable component and electrically connected to the positionsensor and the wear sensor to receive signals therefrom whereby positionand wear of the movable component are determined.

The downhole tool may be a reamer and the movable component is a cutterblock.

In at least one aspect, the disclosure relates to a wear sensor for adownhole tool positionable in a wellbore. The wear sensor includes acore and conductors. The core is positionable about a surface of thedownhole tool, and has a wear surface thereon. The conductors arepositioned at various depths about the core, and are electricallyconnected to electronics in the downhole tool to receive power therefromand send a signal thereto at each of the depths whereby, upon wear ofthe core, a change in the signal of the conductors at the depth of thewear is detectable.

The core may comprise a wear resistant material. The core may comprisetungsten carbide, and/or diamond.

The wear sensor may also comprise a carrier positioned about the core.The carrier may comprise a non-conductive material.

The wear sensor may also comprise a support material positionable aboutthe core. The core may have a cylindrical, polygonal, or a plate shape.The core may comprise core layers and the wear sensor may also comprisevias distributed about the core and electrically connected to theconductors and the core layers.

The conductors may comprise a wire, a cable, and/or a conductive layer.The core may be receivable in a pocket of the downhole tool with thewear surface extending about the surface of the downhole tool.

In another aspect the disclosure relates to a sensor assembly for adownhole tool positionable in a wellbore. The sensor assembly includes acore, conductors, and electronics. The core is positionable about asurface of the downhole tool, and has a wear surface thereon. Theconductors are positioned at various depths about the core. Theelectronics are positioned in the downhole tool, and are electricallyconnected to the conductors. The electronics include a power source togenerate a signal through the conductors and a processor to detect thesignal of the conductors at each of the depths whereby, upon wear of thecore, a change in the signal of the conductors at the depth of the wearis detectable.

The sensor assembly may also comprise an electrical connectorelectrically connecting the conductors to the electronics. Theelectrical connector may be a wire, a cable, and/or a wirelessconnector.

The electronics may comprise a signal converter, an analog to digitalconverter, a multiplexer, pull-up resistors, line resistors, a memory, acommunicator, sensors, a rnicrocontroller, a field programmable gatearray, a receiver, and/or a transmitter.

In another aspect, the disclosure relates to a method of sensing wear ofa downhole tool positionable in a well bore. The method involvesproviding the downhole tool with a sensor assembly, the downhole toolcomprising a tool body. The sensor assembly includes a core andconductors. The core is positionable about a surface of the downholetool, and has a wear surface thereon. The conductors are positioned atvarious depths about the core. The method also involves generating asignal through the conductors, and detecting wear about the surface ofthe downhole tool by detecting changes in the signal of the conductorsas the wear surface is lowed to the various depths of the core.

In another aspect, the disclosure relates to a wear sensor for adownhole tool positionable in a wellbore. The wear sensor includes abase, conductive layers, and vias. The base positionable about a surfaceof the downhole tool. The conductive layers stacked on the base, theconductive layers defining a wear surface. The vias extend through theconductive layers and to the base, and include base vias and conductorvias. The base vias are in electrical communication with the base. Eachof the base vias and each of the conductor vias in electricalcommunication with a corresponding one of the conductive layers. Theconductor vias are in electrical communication with the base viasthrough the corresponding one of the conductive layers. The base iselectrically connected to electronics to generate a signal through thevias whereby, upon wear of the core, a change in the signal of theconductor vias at the depth of the wear is detectable.

The vias may be tubular members extending vertically through theconductive layers from the wear surface to the base, and the vias may bepositioned parallel to each other. The vias may comprise a plurality ofconductor vias distributed about each of the conductive layers. Theconductor vias may comprise ten conductor vias extending along a lengthof the conductive layers.

The conductive layers may comprise copper. The base vias may comprise aconductor extending therethrough, the conductor electrically coupled tothe corresponding one of the conductive layers and to the base.

Each of the conductor vias may comprise a conductor portion electricallycoupled to the corresponding one of the conductive layers and aninsulated portion electrically insulated from a remaining portion of theconductive layers.

In another aspect, the disclosure relates to a sensor assembly for adownhole tool positionable in a wellbore. The sensor assembly includes abase, conductive layers, vias, and electronics. The base is positionableabout a surface of the downhole tool. The conductive layers are stackedon the base, and define a wear surface. The vias extend through theconductive layers and to the base, and include base vias and conductorvias. The base vias are in electrical communication with the base. Eachof the base vias and each of the conductor vias in electricalcommunication with a corresponding one of the conductive layers. Theconductor vias are in electrical communication with the base viasthrough the corresponding one of the conductive layers. The electronicsare electrically connected to the base to generate a signal through thevias whereby, upon wear of the core, a change in the signal of theconductor vias at the depth of the wear is detectable.

The electronics may comprise a power supply electrically coupled to thebase to send the signal through the vias. The electronics may comprise aground. The electronics may comprise signal lines, each of the signallines electrically connecting the corresponding one of the conductivelayers to remote electronics.

The remote electronics may comprise a processor and pull up resistors.The remote electronics may comprise a processor; the electronics maycomprise resistors in each of the signal lines.

The signal lines may be joined by a common output, the common outputelectrically coupling the signal lines to the remote electronics. Theelectronics may comprise a signal converter electrically connected tothe corresponding one of the conductive layers, the signal converterelectrically connected to the remote electronics by at least one of thesignal lines.

The signal converter may comprise one of an analog to digital converterand a multiplexer. The electronics may comprise a signal converter, ananalog to digital converter, a multiplexer, pull-up resistors, lineresistors, a memory, a communicator, sensors, a microcontroller, a fieldprogrammable gate array, a receiver, and/or a transmitter.

In another aspect, the disclosure relates to a method of sensing wellsite parameters about a downhole tool. The method involves deploying thedownhole tool into a wellbore. The downhole tool includes a wear sensorincluding a base, conductive layers, and vias. The base is positionableabout a surface of the downhole tool. The conductive layers are stackedon the base, and define a wear surface. The vias extend through theconductive layers and to the base, and include base vias and conductorvias. The method also involves electrically connecting the base vias andthe base, the conductor vias with a corresponding one of the conductivelayers, and the conductor vias with the base vias through thecorresponding one of the conductive layers; generating signals from thebase, through the base vias, and to the conductor vias in each of theconductive layers; and determining a depth of wear about the surface ofthe downhole tool by measuring the signal over time and detecting achange in the signal as the wear surface wears about the conductivelayers.

The determining may comprise measuring the signal across multiple of theconductor vias distributed about the conductive layers and the detectingmay comprise detecting a change in the signal from multiple of theconductor vias.

The generating signals may comprise passing the signals from each of theconductive layers via a plurality of signal lines to electronics for themeasuring. The generating signals may comprise passing the signals fromeach of the conductive layers via a plurality of signal lines, applyinga resistance to each signal line, and passing the signals to electronicsthrough a combined signal line for the measuring. The generating signalsmay comprise passing the signals from each of the conductive layersthrough an analog to digital converter and to electronics through atleast one signal line for the measuring. The generating signals maycomprise passing the signals from each of the conductive layers througha multiplexer and to electronics through at least one signal line forthe measuring.

In another aspect the disclosure relates to a sensor assembly for adownhole tool positionable in a well bore. The downhole tool includes atool body and a movable component movably positionable about the toolbody. The sensor assembly includes a sensor and electronics. The sensoris carried by the movable component to take well site measurements. Theelectronics are positioned in the movable component, the electronicselectrically connected to the sensor to receive the wellsitemeasurements therefrom whereby well site parameters are determinable.

The sensor may comprise a position sensor coupled to a reference in thetool body of the downhole tool. The sensor may comprise a wear sensorpositioned about a surface of the movable component.

The sensor assembly may also comprise seals positioned about the sensor.The sensor assembly may also comprise a chassis carried by the movablecomponent, the chassis comprising a sidewall with an electronics chamberto receive the electronics therein.

The sensor assembly may also comprise a plug positionable about anopening of the chassis. The sensor assembly may also comprise a bracketto secure the chassis to the movable component.

The sensor assembly may also comprise a disc coupled to the chassis, thesensor comprising a position sensor carried by the disc.

The electronics may be positioned on an electronics board. Theelectronics may comprise batteries. The electronics may comprise asignal converter, an analog to digital converter, a multiplexer, pull-upresistors, line resistors, a memory, a communicator, sensors, amicrocontroller, a field programmable gate array, a receiver, and/or atransmitter.

The sensor assembly may also comprise an electrical connectorelectrically connecting the sensor to the electronics. The electricalconnector may be a wire, a cable, and/or a wireless connection.

In yet another aspect, the disclosure relates to a downhole toolpositionable in a well bore. The downhole tool includes a tool body, amovable component movably positionable about the tool body, and a sensorassembly. The sensor assembly includes a sensor carried by the movablecomponent to take well site measurements, and electronics positioned inthe movable component. The electronics are electrically connected to thesensor to receive the well site measurements therefrom whereby well siteparameters are determinable.

The movable component may comprise a cutter block extendable from thetool body. The sensor assembly may also comprise a chassis carried bythe movable component, the chassis comprising a sidewall with anelectronics chamber therein. The chassis may positioned in a pocketwithin the cutter block.

The cutter block may have at least one port therethrough, the chassisaccessible through at least one port. The sensor may be carried by themovable component, the movable component having a channel extendingbetween the sensor and the chassis.

The downhole tool may also comprise references in communication with thesensors, the references positioned in the tool body of the downholetool.

In another aspect, the disclosure relates to a method of sensing wellsite parameters about a downhole tool. The method involves deploying thedownhole tool into a wellbore. The downhole tool includes a tool body, amovable component, and a sensor assembly. The sensor assembly includes asensor carried by the movable component and electronics carried by themovable component. The method also involves taking wellsite measurementswith the sensor, collecting the well site measurements from the sensorwith the electronics, and determining well site parameters from thewellsite measurements with the electronics.

The deploying may comprise positioning a chassis in the movablecomponent, storing the electronics in the chassis, and coupling thesensor assembly to the electronics.

The method may also comprise positioning a reference in the tool bodyand detecting the reference with the sensor. The method may alsocomprise detecting wear of the downhole tool with the sensor by sendinga signal to the sensor and detecting a change in the sensor upon thewear about the sensor.

In another aspect, the disclosure relates to a sensor assembly for adownhole tool positionable in a well bore penetrating a subterraneanformation. The downhole tool includes a tool body and a movablecomponent movably positionable about the tool body. The sensor assemblyincludes references carried by the tool body, a position sensor carriedby the movable component, a wear sensor positioned about a surface ofthe movable component sensor to detect wear, a chassis carried by themovable component, and electronics. The position sensor is carried bythe movable component, and is positionable about the references todetect when the references are in proximity to the position sensor. Theelectronics are positioned in the chassis and electrically connected tothe position sensor and the wear sensor to receive signals therefromwhereby position and wear of the movable component are determined.

The position sensor and the references may comprise magnets. Theposition sensor may comprise one of north magnetic sensors, southmagnetic sensors, and/or bi-polar sensors.

The position sensor may comprise a disc with the position sensors onupper and lower surfaces thereof. The disc may be connected to thechassis by a stem with a wired connection therethrough, the wiredconnection electrically connecting the position sensors to theelectronics.

The wear sensor may comprise a core having a wear surface and conductorspositioned at depths about the core, the conductors electricallyconnected to the electronics. The chassis may comprise a sidewall withan opening and a plug positioned about the opening.

In another aspect, the disclosure relates to a downhole toolpositionable in a wellbore penetrating a subterranean formation. Thedownhole tool includes a tool body, a movable component movablypositionable about the tool body, and a sensor assembly. The sensorassembly includes references carried by the tool body, a position sensorcarried by the movable component, a wear sensor positioned about asurface of the movable component sensor to detect wear, a chassiscarried by the movable component, and electronics. The position sensoris positionable about the references to detect when the references arein proximity to the position sensor. The electronics are positioned inthe chassis and electrically connected to the position sensor and thewear sensor to receive signals therefrom whereby position and wear ofthe movable component are determined.

The tool body may comprise a drilling tool and the movable component maycomprise a cutter block. The movable component may have a pocket toreceive the chassis therein, and sensor pockets to receive the positionsensor and the wear sensor therein. The movable component may have acommunications channel therethrough and a wired communication link inthe communications channel, the wired communication link electricallyconnecting the wear sensor to the electronics.

The downhole tool may also comprise seals in the communications channel.The references may be spaced apart about a surface of the tool body. Thedownhole tool may also comprise additional electronics in the tool body,the additional electronics electrically connectable to the electronicsin the movable component. The additional electronics may be incommunication with welllsite units.

In another aspect, the disclosure relates to a method of sensingmovement a downhole tool positionable in a well bore penetrating asubterranean formation. The method involves providing the downhole toolwith a sensor assembly. The downhole tool includes a tool body and amovable component movably positionable about the tool body. The sensorassembly includes references carried by the tool body, a position sensorcarried by the movable component, a wear sensor positioned about asurface of the movable component sensor, a chassis carried by themovable component, and electronics positioned in the chassis andelectrically connected to the position sensor and the wear sensor. Themethod also involves detecting the references with the position sensorwhen in proximity to the position sensor, detecting wear with the wearsensor, and determining position and wear of the movable component byreceiving the detecting from the position sensor and the wear sensorwith the electronics.

The detecting the references may comprise changing a signal from theposition sensor to the electronics when the position sensor has amagnetic polarity different from a magnetic polarity of the referencesin proximity thereto. The detecting wear may comprise changing a signalfrom the wear sensor to the electronics when a conductor at a depthwithin a core of the wear sensor is damaged.

In another aspect, the disclosure relates to a sensor assembly for adownhole tool positionable in a well bore penetrating a subterraneanformation. The downhole tool comprises a tool body and a movablecomponent movably positionable about the tool body. The sensor assemblycomprises references and a position sensor. The references comprisemagnets distributed about the tool body, with a portion of the magnetshaving a north polarity and a portion of the magnets having a southpolarity. The position sensor is carried by the movable component as themovable component moves relative to the tool body. The position sensorincludes at least one pair of spaced-apart magnets. Each of the pairscomprising magnets having a north polarity and a south polarityresponsive to the north and south polarity of the reference s whereby aposition of the movable component is determined.

The position sensor may also comprise a bi-polar magnet. The sensorassembly may also comprise a chassis carried by the movable componentand a disc connected to the chassis, the pair of spaced-apart magnetspositioned on opposite sides of the disc.

The references may be linearly spaced along a surface of the downholetool adjacent the movable component. The magnets of the references mayhave alternating north and south polarity.

In another aspect, the disclosure relates to a sensor assembly for adownhole tool positionable in a well bore penetrating a subterraneanformation. The downhole tool comprises a tool body and a movablecomponent movably positionable about the tool body. The sensor assemblyincludes references, a position sensor, and electronics. The referencescomprise magnets distributed about the tool body. A portion of themagnets having a north polarity and a portion of the magnets having asouth polarity. The position sensor is carried by the movable componentas the movable component moves relative to the tool body. The positionsensor comprises at least one pair of spaced-apart magnets. Each of thepairs comprises magnets having a north polarity and a south polarityresponsive to the north and south polarity of the references. Theelectronics are coupled to the position sensor to detect when theposition sensor encounters the references whereby a position of themovable component is determined.

The sensor assembly may also comprise a chassis carried by the movablecomponent, the electronics positioned in the chassis. The sensorassembly may also comprise electrical connections between theelectronics and the position sensor to pass signals therebetween.

Finally, in another aspect, the disclosure relates to a method ofsensing movement of a downhole tool positionable in a wellborepenetrating a subterranean formation. The method involves providing thedownhole tool with a sensor assembly. The downhole tool comprises a toolbody and a movable component movably positionable about the tool body.The sensor assembly includes references and a position sensor. Thereferences comprise magnets distributed about the tool body, with aportion of the magnets having a north polarity and a portion of themagnets having a south polarity. The position sensor is carried by themovable component as the movable component moves relative to the toolbody. The position sensor comprises at least one pair of spaced-apartmagnets. Each of the pairs comprises magnets having a north polarity anda south polarity responsive to the north and south polarity of thereferences. The method also involves detecting the references with theposition sensor when in proximity to the position sensor and determininga position of the movable component by receiving the detecting from theposition sensor.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present disclosure can be understood in detail, a moreparticular description of the invention may be had by reference to theembodiments thereof that are illustrated in the appended drawings. It isto be noted, however, that the appended drawings illustrate exampleembodiments and are, therefore, not to be considered limiting of itsscope. The figures are not necessarily to scale and certain features,and certain views of the figures, may be shown exaggerated in scale orin schematic in the interest of clarity and conciseness.

FIG. 1 depicts a schematic view, partially in cross-section, of a wellsite having a surface system and a subsurface system for drilling awellbore, the subsurface system comprising a well site tool with adrilling assembly and a sensor assembly.

FIGS. 2A and 2B are longitudinal cross-sectional and partialcross-sectional views, respectively, of a portion of the well site tooldepicting the drilling assembly and the sensor assembly.

FIG. 3A is a perspective view of a cutter block of the drillingassembly. FIG. 3B is a longitudinal cross-sectional view of the cutterblock of FIG. 3A taken along line 3B-3B. FIG. 3C is a verticalcross-sectional view of the cutter block of FIG. 3A taken along line3C-3C.

FIG. 4 is a schematic view of the sensor assembly including a wearsensor and a position sensor.

FIGS. 5A and 5B are schematic views of versions of the wear sensor.

FIGS. 5C1-5C3 are perspective, end, and schematic views of a layeredversion of the wear sensor.

FIGS. 5D1-5D5 are schematic views of layers of the layered wear sensor.

FIG. 5E is a schematic view depicting operation of the layered wearsensor.

FIGS. 6A-6B are cross-sectional views of a cutter block in an extendedand retracted position, respectively, the cutter block having a pair ofposition sensors positionable relative to references in the tool body.

FIGS. 6C-6D are a schematic view and graphs depicting operation of acutter block with multiple pairs of position sensors positionable aboutreferences in a tool body.

FIGS. 6E-6F are a schematic view and graphs depicting operation ofanother cutter block with the position sensors in a verticalconfiguration.

FIGS. 6G-6H are a schematic view and graphs depicting operation of thecutter block of FIG. 6E with a bi-polar sensor.

FIGS. 7A and 7B are schematic diagrams depicting electronics of thesensor assembly.

FIG. 8 is a flow chart depicting a method of sensing well siteparameters.

DETAILED DESCRIPTION

The description that follows includes exemplary apparatuses, methods,techniques, and/or instruction sequences that embody techniques of thepresent subject matter. However, it is understood that the describedembodiments may be practiced without these specific details.

The present disclosure relates to a sensor assembly usable with a wellsite tool deployable into a wellbore. The well site tool includes adrilling assembly with a movable component for performing well siteoperations, such as reaming, centering, adjusting, deploying, extending,retracting, and/or other operations that may change a position of themovable component about the well site tool.

The sensor assembly includes a chassis, electronics, and at least onesensor for measuring various parameters. The sensor may be a wear sensorcapable of measuring wear of the well site component over time, and/or aposition sensor capable of measuring movement of the movable component.The wear sensor may be positioned about a surface of the downhole tool.The wear sensor may include electrical conductors at depths along acore. The conductors may send signals that may be monitored. As the corewears over time, the conductors at the worn levels may break, there byaltering the signal in a manner that is detectable. Known depths of theconductors can be used to indicate an amount of wear experienced.

The sensor assembly may be a position sensor in a movable portion of thedownhole tool with references positioned in a moveable or fixed portionof the downhole tool. The position sensor may detect polarity of thereferences as the position sensors moves thereabout so that a positionof the movable component about the downhole tool can be determined.

The sensor assembly may provide information usable by operators (e.g.,drillers) to determine downhole conditions. The information provided maybe used to identify a position of subsurface equipment, as well asvarious wellsite parameters. For example, drillers may be provided withinformation that may be used to determine how a reamer is performing(e.g., detecting whether a cutter block of a reamer is extended orretracted), how to proceed, and/or what to do in another hole. Thesensor assembly may also provide information that may forego the needfor performing additional tests, such as ledge tests, wire line caliperruns, and/or other testing, which may affect non-productive time.

FIG. 1 depicts a schematic view, partially in cross-section, of a wellsite 100. While a land-based drilling rig with a specific configurationis depicted, the present disclosure may involve a variety of land basedor offshore applications. The well site 100 includes surface equipment101 and subsurface equipment 102. The surface equipment 101 includes arig 103 positionable about subterranean formation 104 for performingvarious well bore operations, such as drilling a wellbore 106.

The surface equipment 101 may include various rig equipment 108, such asa Kelly, rotary table, top drive, elevator, etc., provided at the rig103 to operate the subsurface equipment 102. A mud pit 109 may beprovided as part of the surface equipment 101 for passing mud from thesurface equipment 101 and through the subsurface equipment 102. Variousflow devices, such as a pump may be used to manipulate the flow of mudabout the well site 100.

The flow of mud may be used to activate various portions of thesubsurface equipment 102. The subsurface equipment 102 may include awellsite tool 105 including a drill string 110 with a bottom holeassembly (BHA) 112, and a drill bit 114 at an end thereof. The wellsitetool 105 may be subject to forces, such as tension T, compression C,and/or drilling (e.g., rotation, torque) forces F. Fluid from the mudpit 109 maybe passed through the drill string 110, BHA 112, and out thedrill bit 114 as the drill bit 114 is advanced into the formation 104 toform the wellbore 106.

The drill string 110 may include drill pipe, drill collars, coiledtubing or other tubulars used in drilling operations. The BHA 112 is ata lower end of the drill string 110 and contains various subsurfacecomponents for performing subsurface operations. As shown, the BHA 112includes a drilling assembly 116 that may be used to drive the drill bit114. The BHA 112 may also include various other subsurface components,such as motors, stabilizers, a measurement while drilling tool, alogging while drilling tool, a telemetry unit, rotary steerables,pulsers, shock tools, hole enlargers, stabilizers, coring tools, fishingtools, and/or other subsurface components, at least some of which mayhave movable components movable about the BHA 112 and/or wellsite tool105.

In an example, the drilling assembly 116 is a reamer (or hole enlarger)assembly with movable components, such as cutter blocks 118, extendabletherefrom for engagement with a wall of the wellbore. The reamerassembly 116 may be used, for example, to enlarge the hole drilled bythe drill bit 114. Examples of hole enlargers and/or cutter blocks areprovided in US Patent/Application Nos. 2010/0181115, 2012/0055714, U.S.Pat. Nos. 8,307,921, 7,823,663, 7,703,553, 7,958,953, and 6,615,933,previously incorporated herein.

The reamer assembly 116 may be provided with a sensor assembly 120 todetect movement of movable components of the reamer assembly 116. Forexample, the sensor assembly 120 may be used to detect expansion,retraction, and/or position of the cutter blocks 118 about the BHA 112.One or more sensor assemblies 120 may be placed about one or more wellsite components, such as those of BHA 112.

One or more well site units (e.g., controllers) 128 a,b may be providedto operate the well site 100. For example, a surface unit 128 a may beprovided at the surface and a subsurface unit 128 b may be provided inthe well site tool 105. The units 128 a,b may be provided withmeasurement and/or data control devices (e.g., processors, centralprocessing units, etc.) to collect and/or analyze drilling data. Theunit(s) 128 a,b may operate the surface and/or subsurface equipment 101,102 based on the drilling data.

While FIG. 1 shows one drilling assembly 116 in the form of a reamerassembly with two cutter blocks 118 extendable therefrom and a sensorassembly 120 provided for each cutter block 118, other configurationsmay be envisioned. For example, one or more sensor assemblies 120 may beprovided about one or more movable components, such as movable arms,collars, blocks, and/or other features of the BHA 112.

FIGS. 2A and 2B are longitudinal cross-sectional and perspective views,respectively, of a portion of the BHA 112 depicting the reamer assembly116 and the sensor assembly 120 in greater detail. As shown in thesefigures, the BHA 112 includes multiple components, including the reamerassembly 116, a telemetry module 230, and a measurement module 232. TheBHA 112 has a passage 229 for the passage of mud therethrough.

The reamer assembly 116 includes a drill collar (or body) 233 with areamer pocket 236 therein to receive the cutter block 118. The reamerassembly 116 may be provided with electronics 234 and/or be coupled toother modules, such as modules 230, 232, with electronics 234 thereinfor operation thereof. The electronics 234 may be used to activate thereamer assembly 116 and/or the sensor assembly 120.

The telemetry module 230 may provide communication between portions ofthe BHA 112 and other units (e.g. surface and/or subsurface units 128a,b of FIG. 1). The telemetry module 230 may be provided with variouscommunications capabilities, such as wired drill pipe, mud pulse,electromagnetic, acoustics, and/or other communication means. Themeasurement module 232 may be provided with various measurement and/orcommunications capabilities, such as MWD, LWD, and/or others.

The sensor assembly 120 may be coupled to the reamer assembly 116 tocollect data therefrom. The sensor assembly 120 may include sensors 235a-c, a reference (or reference sensor) 237, and a chassis 239positionable about the drilling assembly 116 for measuring well siteparameters. The sensor assembly 120 may be provided with measurementcapabilities, such as detecting a position of the cutter blocks 118and/or measuring well site parameters, such as temperature, pressure,and/or other well site parameters. The sensors 235 a-c may be HallEffect, magnetometer, and/or other types of sensors capable of measuringdesired well site parameters.

Data collected by the sensor assembly 120 may be stored in electronics234 in the sensor assembly 120, or passed via communication links 238 tothe electronics 234 of the other modules and/or to the surface unit 128a and/or subsurface unit 128 b as schematically shown. The telemetrymodule 230, the measurement module 232, and/or other components of theBHA 112 may communicate and/or work with the reamer assembly 116 and/orthe sensor assembly 120. Communication to other well site components inthe BHA 112 may also be established with the sensor assembly 120. Thesensor assembly 120 may be used, for example, as a pass through deviceto allow transmission of data and/or as a monitoring system betweenother well site components in the BHA 112.

As shown in FIG. 2B, the sensor assembly 120 is positioned about thedrilling assembly 116. A portion of the sensor assembly 120 is in thecutter block 118 and a portion is in the drill collar 233. The chassis239 is positioned in the cutter block 118 a variable distance AD fromthe reference 237 in the drill collar (or tool body) 233 as the cutterblock 118 extends and retracts. The cutter block 118 is movablypositionable in the reamer pocket 236 extending into the drill collar233. The sensors 235 a-c are provided about the cutter block 118 tomeasure parameters and/or to measure a position of the reference 237.While three sensors 235 a-c are shown, one or more sensors may beprovided. Seals 231 may also be provided about various portions of thecutter block 118.

One or more of the references 237 and one or more of the sensors 235 a-cmay be provided. Reference 237 may be a magnetic mechanism used totrigger the sensors (e.g., sensor 235 a). Additional accuracy may beprovided to determine movement of the cutter block 118 by adding morereferences 237 detectable by the sensors. By having multiple references237 acting as triggers, the sensors may provide more resolution todetermine the location of the cutter block 118. In at least some cases,the sensors may also determine when the cutter block 118 is stuck.

FIGS. 3A -3C provide perspective, longitudinal cross-section, and radialcross-sectional views, respectively, of the cutter block 118 with aportion of the sensor assembly 120 therein. As shown in these views, thecutter block 118 has a cavity 340 to receive the sensor assembly 120therein. The chassis 239 is in an electronics portion 342 of the cavity340 with the wear sensor 235 b in a sensor portion 344 of the cavity340, and the communication links 238 a,b in a communication channel 346therebetween. Seals 231 are shown in the communication channel 346 tofluidly isolate the electronics 234 in the cavity 340 from the wellbore.

As also shown in these views, the cutter block 118 may also include aport 348 extending through a side of the cutter block 118 and sensor 235a extending from chassis 239. As shown, the position sensor 235 a mayrest in a sensor pocket of the cutter block. The sensor assembly 120 mayhave a plug 345 extendable through the port 348 to connect the chassis239 with an external cable and provide the communication link 238 cthereto. The plug 345 may be secured in place with a bracket 347. Thechassis 239 has the electronics 234 and batteries 350 therein. Anelectronics (e.g., communications) port 352 may also be provided foraccessing the electronics 234 through the cutter block 118.

The electronics 234 may optionally be housed within cavity 340 and/orchassis 239 within a casing, such as a mold. The casing may be used, forexample, to increase the reliability of the system, to isolate theelectronics from the harsh downhole environment, to seal the electronicswithin the cutter block 118, to provide a cushion, and/or for otherreasons.

FIG. 4 shows a schematic diagram depicting the sensor assembly 120 ingreater detail. The sensor assembly 120 is shown as having a cylindricalchassis 239 with the position sensor 235 a and the wear sensor 235 bextending therefrom. The chassis 239 has electronics 234, plug 345 on anend of the chassis 239, and the batteries 350 thereon. A seal 431 isprovided about the plug 345.

The wear sensor 235 b and the position sensor 235 a are connected to theelectronics 234 by communication links 238 a-c. The position sensor 235a is depicted as a disc shaped member attached to the chassis 239 by astern 454. The reference 237 in the drilling assembly 116 is coupled tothe position sensor 235 a via communication link 238 a. Part or all ofthe electronics 234 may be placed inside the cutter block 118. Reference237 may optionally be provided and placed outside the cutter block 118.

The communication links 238 a-c may be direct or indirect, wired orwireless connections for communication between various components. Forexample, the communication links 238 b,c may be a wired, directconnection between the wear sensor 235 b, the position sensor 235 a, andthe electronics (board) 234. The communication link 238 a may be awireless connection between the reference 237 and the position sensor235 a. Variations may be provided, such as a wireless communication linkbetween the reference 237 and the electronics (board) 234.

Part or all of the sensor assembly 120 may be designed and mounted tofacilitate assembly and/or replacement as needed. For example, part orall of the sensor assembly 120 may be mounted into the cutter block 118and sealed by seals 231, 431 from drilling fluid, high pressure and/orany other downhole environment elements that may damage the sensorassembly 118.

FIGS. 5A-5E depict various configurations of a wear sensor. FIGS. 5A and5B are schematic views of wear sensors 535 a,b usable with the sensorassembly 120. FIG. 5A shows a concentric (radial) version of the wearsensor 535 a. FIG. 5B shows a plate (linear) version of the wear sensor535 b. The wear sensors 535 a,b may be used, for example, to detect wearof the cutter block 118 over time.

These wear sensors 535 a,b each include a core 556 a,b, a carrier 558 a,and one or more conductors 560. The core 556 a,b may be, for example, awear and/or impact resistant material (e.g., tungsten carbide,polycrystalline diamond, etc.) to support the wear sensor 535 a,b forengagement with the wellbore wall. The core 556 a,b has one or more ofthe conductors 560 supported therein. The conductors 560 may beelectrical wires, cables, or other devices capable of sending electricalsignals.

The core 556 a,b may be supported by the carrier 558 a. The carrier 558a may be a non-conductive material (e.g., polyamide, elastomer, PEEK,etc.) As shown, the core 556 a,b, carrier 558 a, and/or conductors 560may be of any shape (e.g., elliptical, polygonal, etc.) positionablealong an outer surface of the cutter block 118 (or other component) andextending therebelow.

As shown in FIGS. 5A and 5B, the wear sensors 535 a,b may be providedwith various options, such as a support material 564, connectors 566,and/or other features. One or more layers of various materials capableof operatively supporting the conductors 560 may be provided. Connectors566 may communicatively couple the conductors 560 to electronics 234 foroperation therewith. The connectors 566 may be, for example, electricalwires, cables, and/or other devices capable of sending electricalsignals.

The conductors 560 may be electrically coupled to the electronics 234directly and/or by the connectors 566. The conductors 560 may extendradially and/or linearly about the core 556 a. The surface end 562 ofthe wear sensors 535 a,b may wear over time as the cutter block 118engages the wellbore wall as indicated by the downward arrows. As thesurface end 562 is removed, conductors 560 positioned at variouslocations along the core 556 a,b may be revealed. As the conductors 560are revealed, changes in electrical signals generated therefrom aredetectable with the electronics 234. This information may be used todetermine wear of the cutter blocks 118 over time.

FIGS. 5C1-5E show another version of the wear sensor 535 c in a layeredconfiguration. FIGS. 5C1-5C3 show various views of the wear sensor.FIGS. 5D1-5D5 show each of the layers of the wear sensor 535 c. FIG. 5Eshows operation of the wear sensor 535 c. As shown in these views, thelayered wear sensor 535 c includes core layers 556 c 1-c 5, vias 558 b1,b 2, and one or more conductors 560. The core in this versioncomprises conductive layers 556 c 2-c 5 supported on a base layer 556 c1.

As shown, the core layers 556 c 1-c 5 are horizontal layers wearableover time as the wear sensor 535 c engages a surface of the wellbore 106during operation. The base layer 556 c 1 is at a bottom end thereof withthe conductive layers 556 c 2-c 5 stacked thereon. The stackedconductive layers 556 c 2-c 5 are stacked to define a top wear surfacethat lowers towards the base layer 556 c 1 as each layer 556 c 2-c 5 isremoved by wear over time. Each of the core layers 556 c 1-c 5 include aconductive portion made of a conductive material, such as copper. Thecore layers 556 c 1-c 5 are configured to receivingly andcommunicatively support vias 558 b 1 ,b 2 therein.

Vias 558 b 1,b 2 are elongate, conductive tubular members verticallypositioned in the core layers 556 c 1-c 5. A bottom end of each via 558b 1,b 2 is supported on the base layer 556 c 1 for electricalcommunication therewith. The vias 558 b 1,b 2 may be electrical tubesincluding a conductive tubing made of copper or other conductivematerial. The vias 558 b 1,b 2 may be conductive for electricalcommunication with a given core layer, and have an insulator about aportion thereof to isolate the via from other core layers. The base vias558 b 1 may support the conductors 560 therein for selectivecommunication with the core layers 556 c 1-c 5.

As shown by FIGS. 5D1-5D5, base vias 558 b 1.1-1.5 and conductor vias558 b 2.1-2.5 may be provided through each layer 556 c 1-c 5. Certainbase vias 558 b 1.1-1.5 in each layer may be defined for communicationwith the base layer 556 c 1. In the example shown, each core layer 556 c1-c 5 includes a pair of base vias 558 b 1.1-1.5 and set of 10 conductorvias 558 b 2.1-2.5. The pair of vias 558 b 1.5-558 b 1.2 in eachconductive layer 556 c 5-556 c 2, respectively, communicates with thebase layer 556 c 1. The set of 10 conductor vias 558 b 2.5-2.2 in eachconductive layer 556 c 5-556 c 2, respectively, may be connected inparallel such that conductor vias 558 b 2.5-2.2 are in contact with theconductive layers 556 c 5-c 2 to establish a multi-contact connectionand send a signal to the base layer 556 c 1 through the pair of basevias 558 b 1.5-1.1.

One or more base and/or conductor vias may be dispersed about one ormore layers to generate desired signals. For example, multiple vias maybe dispersed about the layers such that, upon wearing away of one ormore of the vias, the signal is lost. In at least some cases, the entirelayer may be worn away before the signal is lost indicating that thegiven core layer is worn.

Multiple layers may be used to detect depths of wear by detecting whichlayers have lost signal and which are still intact. Multiple vias may beused such that wear of the entire layer may be required before thesignal is terminated. This may be used, for example, to preventsignaling in cases where impact from partial damage (e.g., a gouge) maybreak the connection with a single connector 566. Multiple conductorvias 558 b 2.5-2.2 may be distributed across the layers so that thesignal generated by each layer may indicate whether the layer is intactor not due to damage to one or more vias. For example, if the signalfrom the one via from a layer is lost or changed, which may indicateeither failure to such via, for example, due to a gouge in the layer,such a failure would not indicate wear across the layer. In anotherexample, if the signal to multiple vias in a layer is lost or changed,this may indicate wear across the layer. In this manner, the signal toone or more vias across a given layer may be used to determine if actualwear has occurred and/or prevent false indication of wear across thelayer when only a gouge in the layer has occurred.

As shown in FIG. 5E, the wear sensor 535 c may generate a voltage Vccreadable by a detector, such as electronics 234 of FIG. 4. Theelectronics 234 may have a variety of configurations capable ofdetecting signals from the wear sensor 535 c. For example, theelectronics 234 may include a processor 578 (e.g., microprocessor (μ C))and one or more pull-up resistors 579. The processor 578 may haveinterrupt capabilities, for example, to allow the processor 578 toremain in a low power state during operation.

The electronics 234 may also include or be coupled to a signal converter580 (such as an A/D converter or multiplexer), and/or line resistorsR1-R5. One or more of these components and/or other components (such asthose provided in FIGS. 7A-7B) may optionally be provided. Part or allof the various electronics 234 and/or electrical components may beprovided in the wear sensor 535 c (e.g., at the base layer 556 c 1 ofFIG. 5C2).

The core layers 556 c 1-c 5 may be linked to the electronics 234 invarious configurations, such as in parallel as shown. Each layer may becoupled to the electronics 234 using a separate signal line (e.g.,conductor 560) for each layer joined by a common ground (GND) line asshown. When used with certain electronics, a single line may extend fromthe wear sensor 535 c and the multiple signal lines to provide a singleoutput to the electronics 234 as shown. Optionally, all signal lines mayextend between the wear sensor 535 c and the electronics 234 forcommunication therewith.

The base layer 556 c 1 completes a loop with each layer that allows wearvalues to be communicated with the electronics 234. The voltagegenerated from each layer 556 c 2-5may be measured. The layers may havea given thickness that determines an amount of wear. The thickness maybe used to define a resolution of wear, with a greater thicknessproviding a lower resolution of wear measurement. Complete wear of alayer may ground such layer.

As the core layers 556 c 5-c 1 wear over time, the corresponding vias558 b 1.1-1.5,b 2.1-2.5 wear over time, thereby changing the electricalconnection and signal for the worn layer. Changes in such signal may bedetected by the electronics 234. The output of each layer may be at alow voltage indicating no wear to such layer. Upon wear of the layer anddamage to the connection, a higher voltage may be generated. Suchvoltages may be passed from the wear sensor 535 c to the electronics 234for processing. The signal converter 580 may be used to convert thesignal for measurement by the electronics 234.

In a first basic example, the pull-up resistors 579 may be used toconvert the output signal to high voltage once the layer is worn. Inother words, the layer may be at low voltage Vcc by being tied to aground GND. Once the layer is worn, voltage Vcc jumps from low to highvoltage indicating to the microprocessor (μC) 578 that the layer is nowworn. When the layer that is being measured is fully intact, the voltagewill be low. When the layer is completely removed, the voltage willbegin to measure high due to the pull-up resistor 579. The pull-upresistor 579 may be chosen to minimize effects of drilling fluids thatmay affect measurements made by the electronics 234.

In a second parallel resistor example, the same process is used, exceptthat the number of signals needed to the electronics 234 may be reduced.A different resistor R1-R5 is provided in series with each line from thewear sensor 535 c, with all of the lines joined at the output to theelectronics 234 and linked by a common ground GND to define a voltagedivider circuit as shown. The resistors R1-R5 may be used in addition toor in place of the pull-up resistors 579. The resistor R1-R5 in eachlayer affects the output of this voltage divider circuit. A differenttotal resistance may be provided as the parallel resistance changes witheach trace/layer.

Once the layer is worn, the output changes on the voltage divider. Aseach layer in the wear sensor 535 c wears away, a corresponding line tothe electronics 234 discontinues sending a signal to the electronics234. In this manner, the voltage divider circuit may be used todetermine whether a layer has been worn or not. Based on that voltagevalue, it can be determined if a certain level was worn or not.

In a third multiplexer example, more resolution may be provided by usinga signal converter 580, such as a multiplexer. Resistors R1-R5 are notrequired in this version. The signal lines from the wear sensor 535 cmay be joined by the common ground GND and connected to the electronics234 for measurement. The lines corresponding to each layer in the wearsensor 535 c may be selectively sent to the electronics 234. In otherwords, signals from each layer may be selectively monitored and passedto the electronics 234 by allowing the microprocessor 578 to selectivelyview output from select signal lines. Using the value of the selectlines and voltage level of the output pin, it can be determined whethera given layer is worn or not.

In this example, the multiplexer 580 may be positioned on the base layer556 c 1. One or more signal lines may extend from the multiplexer 580 tothe electronics 234. A reduced number of lines may be provided betweenthe wear sensor 535 c and the electronics 234. This reduced number oflines may optionally be used with an increase d number of layers in thewear sensor 535 c.

In a fourth ADC (analog to digital converter) example, the signalconverter 580 may be an ADC converter used to convert the signalscorning from the different layers into a single digital output that goesto the electronics 234. Resistors R1-R5 and at least some of the linesbetween the wear sensor 535 c and the electronics 234 may be eliminated.That digital output changes as the layers get worn. Based on thatdigital value corning from the ADC 580, the level of wear can bedetermined. The ADC 580 may also be used to poll each layer. The ADC 580may be used to reduce the number of signal lines while enabling a largernumber of layers on the wear sensor to be monitored. Additionally, theADC 580 may be used to increase resolution or total wear measurementcapability.

While a specific configuration is shown with optional electronics,various combinations of part or all of the components shown may be usedto generate desired measurements.

FIGS. 6A-6D show operation of the sensor assembly 120 for detectingposition of the cutter block 118 relative to the drilling assembly 116.FIGS. 6A and 6B show the cutter block 118 in a first and secondposition, respectively. The cutter block 118 of FIGS. 6A-6B has a pairof position sensors 235 a 1,a 2 and a pair of references 237 a 1,a 2.

The pair of position sensors 235 a 1,a 2 are located in close proximityto each other within the cutter block 118. The pair of references 237 a1,a 2 are spaced apart within the drilling assembly 116. Each of theposition sensors 235 a 1,a 2 have an indicator, such as a magnetsensitive to magnetic fields with different polarity (e.g., north (N)and south (S), respectively). Each of the references 237 a 1,a 2 havemagnets with different polarity (e.g., north (N) and south (S),respectively).

The sensors 235 a 1,a 2 may be one or more of the same or differencesensors, such as magnetometers or, Hall Effect sensors, etc., orientatedto detect north and south facing fields. For example, sensors 235 a 1,a2 could be a pair of Hall Effect sensors oriented to detect north andsouth facing fields, respectively.

The sensor assembly 120 is depicted in cutter block 118 as havingmultiple position sensors 235 a 1,a 2 in communication with electronics234 in chassis 239 and references 237 a 1,a 2 along opposite ends of apath of travel of the cutter block 118 of the drilling assembly 116. Theposition sensors 235 a 1-a 2 may be provided with a polarity switchableupon encountering references 237 a 1,a 2 of different polarity.

As the position sensors 235 a 1,a 2 are positioned near the reference237 a 1, the position sensor 235 a 1 with N polarity is repelled by thereference 237 a 1 having the same polarity N. The position sensor 235 a1 is thereby shifted and sends an ‘on’ signal detectable by theelectronics 234. In the case of FIG. 6A, the electronics 234 detect theshift by the position sensor 235 a 1 and determines that cutter block118 is in the retracted position. In the case of FIG. 6B, theelectronics 234 detect the shift by the position sensor 235 a 2 with thesame polarity as the reference 237 a 2 and determines that cutter block118 is in the extended position.

As the sensors 235 a 1,a 2 move relative to references 237 a 1,a 2, thesensor 235 a 1,a 2 with the same polarity as the adjacent reference 237a 1,a 2 (or matching sensor) sends an ‘on’ signal detectable by theelectronics 234. As the sensor moves away from the correspondingreference, this sensor sends an ‘off’ signal detectable by theelectronics. In the event that both position sensors 235 a 1,a 2 are inthe ‘off’ state, the electronics 234 determine that the cutter block 118is between references 237 a 1,a 2. The electronics 234 may activelymonitor changes in the sensor(s) 235 a 1,a 2 and/or references 237 a 1,a2 as the cutter block 118 moves. The electronics 234 may also determinewhether the cutter block 118 is extended or not, determine when a changeoccurred, and/or capture (e.g., and/or send) data from the sensors 235 a1,a 2.

FIGS. 6C-6D depict operation of another sensor assembly 120′ andmeasurement generated thereby. The sensor assembly 120′ is similar tothe sensor assembly 120 of FIGS. 6A-6B, except that the sensor assembly120′ is provided with multiple pairs of position sensors 235 a 1,a 2 and235 a 3,a 4 positioned in the cutter block 118, and multiple references237 a 1-a 9 positioned in the drilling assembly 116. Line 668 b showsthe position of the cutter block 118 as it moves back and forth aboutthe drilling assembly 116. The line 668 b begins in a retracted positionat point A, peaks at the extended position at point B, and returns tothe retracted position at point C.

Each of the pairs of position sensors 235 a 1,a 2 and 235 a 3,a 4 arespaced apart within the cutter block 118. The pair of position sensors235 a 1,a 2 have polarity N,S, respectively. The pair of positionsensors 235 a 3,a 4 have polarity N,S, respectively. As shown in FIG.6C, the pairs of position sensors 235 a 1,a 2 are spaced a distance 13apart from sensors 235 a 3,a 4.

The references 237 a 1-a 9 are positioned in series within the drillingassembly 116. As shown, the references 237 a 1-a 9 linearly disposedalong a path of travel of the cutter block 118 along the drillingassembly 116, but may be in various positions. Each of the references237 a 1-a 9 have a width d, and a magnetic polarity of north (N) andsouth (S) as indicated by the arrows.

As the cutter block 118 and the pairs of position sensors 235 a 1-a 4move relative to the references 237 a 1-a 9, the position sensors 235 a1, a 2, a 3, a 4 are activated to generate a signal detectable by theelectronics 234. An example signal generated by the position sensors 235a 1,a 2 is depicted by line 668 b 1 and sensors 235 a 3,a 4 is depictedby line 668 b 2 in the graph of FIG. 6D. Line 668 b 1 depicts output bysensors 235 a 1,a 2, and line 668 b 2 depicting output by sensors 235 a3,a 4 as the cutter block 118 moves relative to references 237 a 1-a 9over time t.

The lines 668 b,b 1,b 2 refer to signals represented by the followingequations:

$\begin{matrix}{{1 = {{\frac{{2{nd}} + 1}{2}n} = 1}},2,{3\mspace{14mu} \ldots}} & {{Eqn}.\mspace{14mu} (1)} \\{{\Delta \; x} = {{n\_ flips}*{d/2}}} & {{Eqn}.\mspace{14mu} (2)}\end{matrix}$

where Δx represents the x position of the cutter block, n_flips is thenumber of times either sensor flips from north to south, and d is thespacing of the references. Equation (1) describes the position 1 of thereferences, where n is a counter representing each reference. Equation(2) describes the sum of the flips from sensor 235 a 1 and sensor 235 a2 times one half the spacing of the magnets for unidirectional motion.

Line 668 b 1,b 2 are depicted as square waves generated by pairs 235 a1,a 2 and 235 a 3,a 4, respectively, as they encounter the references237 a 1-a 9. The square waves peak in along the curve as an N polarityof the reference is encountered by a corresponding sensor.

Because of the spacing being offset by half the width of the reference237 a 1-a 9, the pairs of sensors 235 a 1,a 2 and a 3,a 4 ‘take turns’flipping as long as the motion of the cutter block 118 is in the samedirection. The signal generated by the sensors 235 a 1,a 2 createspulses that can be counted to determine the amount of motion in adirection, with a resolution of half (½) a width d of the reference 237a 1-a 9.

When reversing direction, one of the pairs of sensors 235 a 1,a 2 and235 a 3,a 4 may alternate twice before the other sensor will alternate.The pairs of sensors 235 a 1,a 2 and 235 a 3,a 4 may then ‘take turns’flipping just like when the cutter block 118 was traveling originally.By counting pulses in each direction and detecting direction changes, alocation of the cutter block 118 can be known at all times. Also, aspeed of motion of the cutter block 118 can be monitored part or all ofthe time.

FIGS. 6E-6F depict operation of another version of the sensor assembly120″ and measurement generated thereby. The sensor assembly 120″ issimilar to the sensor assembly 120′ of FIGS. 6C-6D, except that thesensor assembly 120″ is shown as including the position sensor 235 awith a north position sensors 235 a 1 and a south position sensor 235 a2 on either side thereof. The references 237 a 1-a 9 and thecorresponding graphs 668 b, b 1, b 2 of FIG. 6F are substantially thesame as in FIGS. 6C and 6D.

In this example, the north and south position sensors 235 a 1,a 2 arepositioned on opposite sides of a disc portion of the position sensor235 a and separated by a distance 13 defined by a width of the discportion. For example, spacing may be provided between north and southsensors to remove the possibility of seeing repeating conditions. Thespacing may be, for example, smaller than the width of the magnets.

FIGS. 6G and 6H depict operation of another version of the sensorassembly 120′″. This sensor assembly 120′″ is similar to the sensorassembly 120″ of FIGS. 6G and 6H, except that an additional northbi-polar sensor 235 a 5 is also provided and the reference magnets 237 a1-a 14 are shown in a different configuration. The bi-polar sensor 235 a5 is depicted as being adjacent to the north sensor 235 a 1, but couldbe at various positions. The bi-polar sensor 235 a 5 may be a northdetecting sensor (NB) that flips logic levels upon sensing an oppositepole to detect, for example, a position that is in between a fullyretracted and fully expanded position of the cutter block 118.

The movement of the sensor assembly 120′″ about the drilling assembly116 generates the graphs 668 c-c 3. The reference magnets 237 a 1-14 areshown with north sensor magnets spaced from north sensor magnets with adistance d therebetween. The north and south sensor magnets are alsoshown adjacent other south sensor magnets. Similar to the graphs 668 b1-b 2 of FIGS. 6D and 6F, the north and south sensor magnets 235 a 1, a2 generate similar signals 668 c 1, c 2 that change every time anopposing references 237 a 1-a 14 is detected. However, the addition ofthe bi-polar sensor 235 a 5 generates a different graph 668 c 3 whichindicates a change in the signal only when the references switch from aN to S or from an S to N polarity.

As shown by FIGS. 6A-6H, various configurations of position andreferences may be provided for use in the sensor assembly and/ordrilling assembly. Various combinations or variations of the sensorsprovided herein may be used to generate various outputs for detectingposition.

FIGS. 7A and 7B are schematic diagrams depicting example electronicconfigurations of the sensor assembly 120 and the electronics 234. Asshown, the sensor assembly 120 includes a sensor 235 a,b,c connectableto the electronics 234 and a surface unit 128 a. Part or all of theelectronics 234 may be positioned in various locations, such as in themovable portion (e.g., reamer) and/or the drill collar of the drillingassembly (see, e.g., FIGS. 2A,2B).

As shown, the electronics 234 may include a memory 770, communicator772, sensors 774, ADC (analog to digital)/DAC(digital to analog) 776,power supply 777, and/or processor 778. The memory 770 may be anystorage device, such as flash memory, and/or other devices. Theelectronics may monitor measurements of the sensor(s) 235 a-c and storedata in the memory 770. The memory 770 may be accessed for localprocessing, and/or streamed to the surface for real time feedback.

The communicator 772 maybe an antenna, signal amplifier, transceiver, orother device for providing communication between the sensor assembly 120and other devices, such as depicted in FIGS. 1 and 2A. Data collectedand/or stored in memory 770 may be downloaded later at surface forfurther analysis and/or streamed via various telemetry means, such asthose described herein.

The sensors 774 may include various measurement devices, such asmagnetometers, accelerometers, gyros, gauges, and/or other devicescapable of measuring various parameters, such as temperature, pressure,position, polarity, movement, rotation, orientation, etc.

The external ADC (Analog to digital)/DAC (digital to analog) 776 maybeused to capture the signals from sensors 235 a-c and send them to theelectronics 234 for processing on processor 778 or recording to memory770.

The power supply 777 may be used to condition a power source, such as abattery, power supply, and/or other device. As soon as the sensorassembly 120 is powered on, the electronics 234 may begin monitoring thesensors 235 a-c and record the data to memory 770 for analysis. In orderto preserve power and memory space, the drilling assembly (e.g., 116 ofFIG. 1) may be shut down regularly for part of the drilling time andcome back on to take measurements. Using this method, the drillingassembly may reach longer run times and still give the desired dataabout the performance of the reamer.

The processor 778 may be one or more devices capable of processingsignals and/or data. For example, the processor 778 may include an ADC(analog to digital)/DAC (digital to analog)/GIO 780, microcontroller(μC)/DSP (digital signal processing)/FPGA (field programmable gatearray) 782, UART (universal asynchronous receiver, transmitter) 784,and/or other electrical devices. Part or all of the items in theprocessor 778, such as the ADC/DAC/GIO 780 and microcontroller/FPGA 782may be in the communicator 772. For example, the processor may be amicrocontroller and/or similar processor that handles all the processes,such as measurement logging, writing to flash memory and/or streaming tosurface.

The electronics 234 may include other options, such as real time clock(counter) 786. Part or all of the electronics, such as the real timeclock 786, may run on a separate power source, or other means to keeptrack of time if a reset were to happen downhole. One or more of thedevices may be provided on one or more electrical boards, such as thetwo boards 787 a,b as depicted in FIG. 7A.

The electronics 234 may include other features, such as those depictedherein. In an example, the microcontroller 782 may use an interrupt tooperate in a low-power state while tracking position with the positionsensors herein. The microcontroller 782 may also be used to measurevoltage levels of the various sensors using a general input to themicrocontroller or an internal/external signal converter (e.g., ADC 580of FIG. 5E). The various sensors (e.g., 235 a-c or 535 c) can be wiredvia the signal converter (e.g., multiplexer 580 of FIG. 5E) to samplesequentially and reduce the number of wires used with wear sensor 535 c(or other sensors).

FIG. 8 depicts a method 800 of sensing wellsite parameters. The method800 involves 890—deploying a well site tool with a drilling assembly anda sensor assembly into a wellbore. The drilling assembly comprises abody (e.g., drill collar) and a movable member. The sensor assemblyincludes a chassis and at least one sensor for measuring wellsiteparameters (e.g. vibration, temperature, revolutions per minute, etc.)as described herein.

The sensors comprise a wear sensor and a position sensor. The wearsensor comprises a core with conductors thereabout, and a wear surfacepositionable about an outer surface of the drilling assembly. Theposition sensor comprises a magnetic sensor positionable in the movablemember and a reference in the body.

The method also involves 892—sensing wear with the wear sensor bydetecting a number of the conductors removed as portions of the wearsensor wear away, 894—moving the movable member about the body, and896—sensing position of the movable member with the position sensor bydetecting a reference with the position sensor.

Other portions of the method may be performed, such as measuringprocessing data collected by the sensor(s) and/or communicating the dataabout the wellsite. The method(s) may be performed in any order andrepeated as desired.

It will be appreciated by those skilled in the art that the techniquesdisclosed herein can be implemented for automated/autonomousapplications via software configured with algorithms to perform thedesired functions. These aspects can be implemented by programming oneor more suitable general-purpose computers having appropriate hardware.The programming may be accomplished through the use of one or moreprogram storage devices readable by the processor(s) and encoding one ormore programs of instructions executable by the computer for performingthe operations described herein. The program storage device may take theform of, e.g., one or more floppy disks; a CD ROM or other optical disk;a read-only memory chip (ROM); and other forms of the kind well known inthe art or subsequently developed. The program of instructions may be“object code,” i.e., in binary form that is executable more-or-lessdirectly by the computer; in “source code” that requires compilation orinterpretation before execution; or in some intermediate form such aspartially compiled code. The precise forms of the program storage deviceand of the encoding of instructions are immaterial here. Aspects of theinvention may also be configured to perform the described functions (viaappropriate hardware/software) solely on site and/or remotely controlledvia an extended communication (e.g., wireless, internet, satellite,etc.) network.

While the embodiments are described with reference to variousimplementations and exploitations, it will be understood that theseembodiments are illustrative and that the scope of the inventive subjectmatter is not limited to them. Many variations, modifications, additionsand improvements are possible. For example, various combinations of oneor more of the features herein may be provided about one or more movableor non-movable components of a well site tool to sense and/or determineone or more well site parameters.

Plural instances may be provided for components, operations orstructures described herein as a single instance. In general, structuresand functionality presented as separate components in the exemplaryconfigurations may be implemented as a combined structure or component.Similarly, structures and functionality presented as a single componentmay be implemented as separate components. These and other variations,modifications, additions, and improvements may fall within the scope ofthe inventive subject matter.

Insofar as the description above and the accompanying drawings discloseany additional subject matter that is not within the scope of theclaim(s) herein, the inventions are not dedicated to the public and theright to file one or more applications to claim such additionalinvention is reserved. Although a very narrow claim may be presentedherein, it should be recognized the scope of this invention is muchbroader than presented by the claim(s). Broader claims may be submittedin an application that claims the benefit of priority from thisapplication.

1-45. (canceled)
 46. A sensor assembly, comprising: a sensor to becarried by a movable component movably positionable about a tool body ofa downhole tool, the sensor to take wellsite measurements and thedownhole tool positionable in a wellbore; and electronics positionablein the movable component, the electronics to electrically connect to thesensor to receive the wellsite measurements from the sensor, thewellsite measurements usable to determine wellsite parameters.
 47. Thesensor assembly of claim 46, wherein the sensor comprises a positionsensor to communicate with a reference positionable in the tool body ofthe downhole tool.
 48. The sensor assembly of claim 46, wherein thesensor comprises a wear sensor positionable about a surface of themovable component.
 49. The sensor assembly of claim 46, furthercomprising seals positioned about the sensor.
 50. The sensor assembly ofclaim 46, further comprising a chassis to be carried by the movablecomponent, the chassis comprising a sidewall with an electronics chamberto receive the electronics therein.
 51. The sensor assembly of claim 50,further comprising a plug positionable about an opening of the chassis.52. The sensor assembly of claim 50, further comprising a bracket tosecure the chassis to the movable component.
 53. The sensor assembly ofclaim 50, further comprising a disc to couple to the chassis, the sensorcomprising a position sensor to be carried by the disc.
 54. The sensorassembly of claim 46, wherein the electronics are positioned on anelectronics board.
 55. A downhole tool, comprising: a tool body; and amovable component movably positionable about the tool body, the movablecomponent carrying a sensor to take wellsite measurements, the movablecomponent housing electronics electrically connected to the sensor toreceive the wellsite measurements from the sensor, wherein the wellsitemeasurements are usable to determine wellsite parameters.
 56. Thedownhole tool of claim 55, wherein the sensor comprises a positionsensor to communicate with a reference positioned in the tool body. 57.The downhole tool of claim 55, wherein the sensor comprises a wearsensor positioned about a surface of the movable component.
 58. Thedownhole tool of claim 55, further comprising a chassis carried by themovable component, the chassis comprising a sidewall with an electronicschamber to receive the electronics therein.
 59. The downhole tool ofclaim 58, further comprising a plug positioned about an opening of thechassis and a bracket to secure the chassis to the movable component.60. The downhole tool of claim 58, further comprising a disc coupled tothe chassis, the sensor comprising a position sensor carried by thedisc.
 61. A method, comprising: deploying a downhole tool with a sensorassembly into a wellbore, the sensor assembly comprising a sensorcarried on a moveable component of the downhole tool, the moveablecomponent positionable about a tool body of the downhole tool, thesensor assembly further comprising electronics housed within the movablecomponent and to receive wellsite measurements from the sensor;performing a wellsite measurement using the sensor; and using thewellsite measurement to determine a wellsite parameter.
 62. The methodof claim 61, further comprising using the sensor and a referencepositioned in the tool body to detect a position of the movablecomponent.
 63. The method of claim 62, further comprising moving themovable component about the tool body.
 64. The method of claim 61,further comprising using the sensor to detect wear, the sensorpositioned about a surface of the movable component.
 65. The method ofclaim 64, wherein the sensor comprises a core having multipleconductors.